Removal of sulfur compounds from gas streams has been of considerable importance in the past and is even more so today due to environmental considerations. Gas effluent from the combustion of organic materials, such as coal, almost always contain sulfur compounds and sulfur removal processes have concentrated on removing hydrogen sulfide since it has been considered a significant health hazard and because it is corrosive, particularly when water is present. With increasing emphasis on eliminating or minimizing sulfur discharge to the atmosphere, attention is turning to removal of other sulfur compounds from gas streams.
Sulfur contaminants in natural gas streams include hydrogen sulfide, mercaptans, sulfides, and disulfides which due to their odorous nature can be detected at parts per million (ppm) concentration levels. Thus, it is desirable for residential and commercial users of natural gas to have concentrations of mercaptans lowered to 1 ppm and total concentrations of sulfur compounds to 20 ppm or less.
Numerous natural gas wells produce what is called in the industry as "sour gas." "Sour gas" is natural gas that contains hydrogen sulfide, mercaptans, sulfides and disufides in concentrations that make its use unacceptable. Considerable effort has been expended to find an effective and cost efficient means to remove these objectionable sulfur compounds from natural gas.
Transmission companies that purchase natural gas from well owners and then distribute to consumers are very critical of sulfur content and require total sulfur content to be less than 30 ppm. Thus, owners of sour gas wells that exceed the 30 ppm limit are constantly searching for new and more efficient means to make their gas salable.
A number of processes are known for the removal of H.sub.2 S from natural gas streams. Processes presently available can be categorized as those based on physical absorption, solid absorption or chemical reaction. Physical absorption processes suffer from the fact that they frequently encounter difficulty in reaching the low concentration of hydrogen sulfide required in the sweetened gas stream. Solid bed absorption processes suffer from the fact that they are generally restricted to low concentrations of H.sub.2 S in the entering gas stream. Chemically reacting processes in general are able to meet sweet gas specifications (primarily H.sub.2 S concentrations) with little difficulty; however, they suffer from the fact that a material that will react satisfactorily with H.sub.2 S will also react with CO.sub.2. Above all, the processes presently available do not effectively provide for the removal of mercaptans, sulfides and disulfides.
An example of a chemically reactive process is the ferric oxide fixed bed process, wherein the reactive entity is ferric oxide (Fe.sub.2 O.sub.3) impregnated on an inert carrier. This process is good for the removal of H.sub.2 S but does not appreciably remove mercaptans or other sulfur compounds. The bed can be regenerated; however, the number of regenerations is limited by the buildup of elemental sulfur upon the bed.
The iron oxide or "dry box" process was one of the first developed for removing H.sub.2 S from gas streams. It was introduced in England about the middle of the 19th century and is still widely used in many areas in special applications. See U.S. Pat. Nos. 632,400 and 1,934,242.
The iron sponge method of sulfur removal from natural gas has been widely used during the past quarter century and has been reported in detail in the literature. See, for example, Taylor, D. K., "High Pressure Dry Box Purification;" Proceedings Gas Conditioning Conference, University of Oklahoma, 1956, page 57; and The Oil and Gas Journal, November and December 1956, a series of 4 articles; and Zapffe, F., "Practical Design Consideration For Gas Purification Processes," The Oil and Gas Journal, Sept. 8, 1958, page 100; and Sept. 10, 1962, page 135.
Typically, the iron oxide process apparatus is two towers filled with an inert carrier that is impregnated with iron oxide. Each tower has a means for the injection of water and air so as to allow for regeneration. Ordinarily at least two iron oxide beds will be used in order to provide for continuous operation. "Sour gas" enters the top of the bed and flows downward contacting the iron oxide. Sweetened gas is removed from the bottom of the vessel. The vessel not in operation would normally be shut down for removal or regeneration of the exhausted iron oxide. In the piping and operation of the process, provisions must be made for the introduction of water and maintenance of a slightly basic pH. Water must be added to this process or the gas will gradually dehydrate the ferric oxide, thus causing it to lose its activity.
There are several known forms of ferric oxide. The ferric oxide is dispersed on materials of large surface and light weight. The most frequently used material is wood shavings or chips. Dispersing the iron oxide in this way provides a relatively large suface area to weight ratio and maximizes contact between the gas stream and the iron oxide.
The iron oxide process can be operated on a batch basis or continuously, the difference depending upon the technique used for regeneration. When a batch process is used the tower is operated until the bed becomes saturated with sulfur and H.sub.2 S begins to appear in the sweetened gas stream. At this point the tower is removed from sweetening service and regenerated by circulating gas containing a small amount of air through the bed. Oxygen concentration of the regeneration stream is normally held below 3 percent because of the highly exothermic nature of the regeneration reaction. In continuous service a small concentration of oxygen may be added to the "sour gas" before entry to the bed. The oxygen in the air reacts with iron sulfide previously formed to regenerate it at the same time ferric oxide is reacting with H.sub.2 S in the gas. Each system has advantages and disadvantages and the choice between batch regeneration and continuous regeneration is based on economic factors which differ from installation to installation.
Theoretically, one pound of ferric oxide will react with 0.65 lbs. of hydrogen sulfide, In field operation this level is never reached. Generally, at 80-85% of theory, H.sub.2 S will begin to break through and show up in the gas stream. At this point the bed is shut down and regenerated. For continuous regeneration, D. K. Taylor, The Oil and Gas Journal, 54, 125 (Nov. 5, 1956); 54, 260 (Nov. 19, 1956); 54, 139 (Dec. 3, 1956); 54, 147 (Dec 10, 1956); reports that about 2.5 lbs of sulfur may be removed per pound of iron oxide before the oxide must be replaced.
In natural gas service, pressures are normally high and pressure drop through the bed is not a serious factor.
It has been reported that cycle time of an iron sponge unit in the field is usually 30 days. A long cycle time is desired to minimize bed replacement costs. Regardless of the regeneration methods that are employed today, the bed will eventually plug with sulfur and have to be replaced. This required manual labor which is expensive. Taylor, in the reference above, gives an excellent summary of points to consider in the design of towers for an iron oxide process for ease of bed replacement and operation.
Primarily, the iron sponge process has been applied to the removal of hydrogen sulfide. The iron sponge will also remove minute amounts of mercaptans from a natural gas stream but this process is not well characterized nor is it efficient.
The affinity of iron oxide for hydrogen sulfide and mercaptans is quite different. While the iron oxide has a strong persistent affinity for hydrogen sulfide, its capacity for removal of mercaptans in the presence of hydrogen sulfide is much lower. This results in "break out" of mercaptans in the early stages of metal oxide bed life. Thus, in order to maintain the desired level of sulfur compounds in the treated stream it is necessary to periodically regenerate the oxide. The data obtained utilizing the process of the present invention indicates that this is very efficiently carried out by periodic or continuous treatment of the oxide bed with an oxidizing agent and an amine, which also provides an unexpected improvement in the oxide's ability to remove mercaptans.
U.S. Pat. No. 4,278,646 discloses a method wherein hydrogen sulfide is removed from a gas stream by contacting the stream with an aqueous solution of ferric ion chelated with an aminopolycarboxylic acid at a pH of 3.5 to 5. This patent discloses a method wherein an aqueous solution of iron chelated with an aminopolycarboxylic acid is used to remove H.sub.2 S from a gas stream. The solution also contains ammonia or an aliphatic, alicyclic or heterocyclic primary or secondary amine in a proportion sufficient to prevent precipitation of iron from the solution.
U.S. Pat. No. 4,238,463 discloses a method for the removal of hydrogen sulfide from gases using iron oxide, wherein a liquid containing a primary or secondary amine is introduced onto the iron oxide-containing solids. This patent utilizes an amine to prevent the treatment beds from hardening into a cohesive mass which is resistant to conventional removal means. Specifically, U.S. Pat. No. 4,238,463 disclosed the addition of a primary, or preferably a secondary amine, to a bed of iron sponge. In addition, U.S. Pat. No. 4,238,463 uses the amine as a solution or suspension of an amine, such as a water solution, but it is preferably a nonaqueous liquid having the amine in solution. A preferred nonaqueous solvent is dimethylsulfoxide. Further, the aqueous solution of the amine was added to the soda ash liquid normally used to maintain an alkaline condition in the bed. The amine solution was then added to the iron sponge every seven days. This patent does not suggest or disclose the beneficial effects of concurrently or intermittently adding an amine, such as ammonia hydroxide, and an oxidant to the iron sponge bed, to accomplish economical and effective removal of sulfur compounds from a gas stream.
A process which improves the ability of an iron sponge to remove sulfur compounds from a gas stream is in demand. The process of the present invention accomplishes effective and economical removal of sulfur compounds from a gas stream through the use of an oxidizing agent and an amine in combination with a metal oxide treatment bed. The reaction of ferric oxide with hydrogen sulfide has been well documented, however, the literature and publications do not disclose or suggest a method in which an oxidizing agent and an amine are added to a metal oxide bed so as to enhance the ability of the oxide bed in the removal of H.sub.2 S and mercaptans from a gas stream. Further, the literature and the referred to patents do not suggest or disclose the fact that the use of an amine and an oxidant exhibit a synergistic effect.
It is the novel and unobvious use of an oxidizing agent and an amine in a process to remove sulfur compounds from a gas stream that comprises at least a portion of the present invention.